1. Field of the Invention
This invention pertains to apparatus for use in wells. More particularly, pressure-containing apparatus is provided for use in high-pressure, high-temperature wells where wall thickness of apparatus is to be minimized and material selection is limited by well conditions.
2. Description of Related Art
With energy prices at all time highs, companies involved in the discovery and production of hydrocarbons are pursuing deeper offshore oil and gas plays. As well depths increase, well architecture becomes more challenging. Geologists, geophysicists and petroleum engineers understand that as well depths increase, so does formation pressure and temperature. It is estimated that pressures of 30,000 psi and 500 deg F. and beyond may become commonplace in future wells. The industry acronym for High-Pressure and High-Temperature wells is HPHT. As HPHT conditions present themselves in deep wells, the equipment needed to safely complete and produce HPHT wells must be developed to withstand safely the rigors of these extreme conditions.
Industry is developing methods and materials to drill the HPHT wells safely, but technology gaps in equipment placed in the wells for producing the wells, called “well completion equipment,” also must be addressed. This includes, but is not limited to devices that are normally larger diameter than the tubing, such as subsurface safety valves, packers, flow control devices (e.g., sliding sleeves), tubing hangers, on-off attachments, and gas lift or instrument mandrels as well as equipment normally the same diameter as tubulars that would preferably be smaller in diameter, as least in some segments of a well, such as production tubing, liners, expansion joints and their connectors. Several papers have been published recently addressing and discussing “gaps” in current technology (for examples, “Ultra Deep HPHT Completions: Classification, Design Methodologies and Technical Challenges, OTC 17927, Offshore Technology Conference, Houston, Tex., May. 2006; “HPHT Completion Challenges,” SPE 97589, Society of Pet. Engrs., May, 2005).
Substances present in fluids produced from HPHT wells are often detrimental to materials that form tubulars and well completion equipment. One of the worst substances is hydrogen sulfide (H2S), which can cause stress corrosion cracking, especially of materials that have high yield strength. Another substance that is often present in HPHT wells is carbon dioxide (CO2), which can cause weight loss corrosion. The National Association of Corrosion Engineers (NACE) has developed guidelines for selecting materials that can be used in the presence of adverse wellbore chemistry. Most often these “NACE materials” fall in the mid-range of material hardness and yield strength.
Additionally, there is recognition among mechanical engineers that guidelines and practices for the safe design of equipment at 15,000 psi and 300° F. are vastly different for the requirements of 30,000 psi and 500° F. As an outgrowth of this knowledge, The American Petroleum Institute (API) is in the process of adopting the requirements of ASME Section VIII Division III into the design requirements of downhole equipment. Section VIII Division III practice requires that Ultra High Pressure Vessels have the allowable stress on materials de-rated as a result of temperature and that a fracture analysis be performed as a part of the design realization process. The simply stated result is that the wall thickness of pressure-containing devices must be very thick if homogeneous NACE materials are used in downhole pressure-containing vessels.
When drilling a well, costs are much higher as depth increases. A similar relationship exists with the diameter of the hole being drilled. Larger diameter, deeper holes become prohibitively expensive unless production flow area (inside diameter of the production tubing) is maximized. Operators want the largest possible flow area in the smallest possible hole. The economic viability of a project is determined by the flow rate from the well. For deep, expensive wells, the production flow area (diameter of the tubing) must often be 5½-in, 7-in, or in some cases 9⅝-in. The design of the well must have its genesis at the inside diameter of the production tubing and work outward to determine what diameter hole must be drilled.
These factors serve to work against each other in the following summarized manner. Wellbores must be deeper to reach pay zones. Production flow areas must be maximized and the hole diameter must be minimized for the well to be economic. The cost of drilling a well is much more expensive as the diameter and depth each increase. Materials must be tailored to the environment, but use of the strongest materials may be inadvisable or prohibited due to NACE requirements to avoid chemical attack. Design practices require thicker and thicker walls to accommodate these factors. Smaller drilled holes, bigger flowing bores, and thicker wall requirements are conflicting requirements.
What is needed is the development of a pressure-containing body that minimizes wall thickness, uses NACE materials where exposed to production fluids, fits in the smallest possible drilled and cased hole, and yields the largest possible flow area for the well. Use of such a body or device can significantly improve the economic viability of new wells.